Solvent-based Recovery Research Articles

Research and Development at Universities: Worldwide Change in Petroleum Engineering

The fundamental properties of hydrocarbons and the basics of drilling will always remain the same. Nevertheless, innovation in petroleum engineering by researchers at universities around the world is changing the face of oil and gas drilling and production in the 21st century. In addition to traditional approaches, technologies for enhanced production from mature fields; production methods for unconventional resources such as tight gas, methane hydrate, and heavy oil; and experimental nanotechnology applications today are critical and increasingly are a part of petroleum engineering research and technology development. Schulich School of Engineering, University of Calgary, Canada The upstream research at Schulich’s Department of Chemical and Petroleum Engineering concentrates on improving the exploitation of Canadian unconventional oil and gas resources such as heavy oil and bitumen, and tight gas formations. The department has a dozen research teams, said professor Brij Maini. The In Situ Combustion Research Group specializes in laboratory and numerical simulation studies of the in-situ combustion of heavy oils, and high-pressure air injection in light oil reservoirs. The faculty’s EnCana/Paleontological Society of Canadian Institute of Mining, Metallurgy, and Petroleum Endowed Chair heads the department’s joint industry project studying the geomechanics of shale gas. The CMG Foundation Chair in Reservoir Simulation is developing fast and reliable reservoir simulators for the recovery of oil, gas, and coal. The NSERC Industrial Research Chair in Heavy Oil Properties and Processing is researching the properties and phase behavior of heavy oil and solvents. Schulich’s SHARP (Solvent/Heat Assisted Recovery Processes) consortium is supported by 11 local and international companies. The improved heavy oil science and technology group is studying various aspects of heavy oil recovery technology, including cold heavy oil production with sand, and solvent-based recovery processes and steam additives for steam injection-based processes.

Technology Development for Solvent-Based Recovery of Heavy Oil

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 150706, ’An Integrated Technology-Development Plan for Solvent- Based Recovery of Heavy Oil,’ by Thomas J. Boone, SPE, Imperial Oil Resources, and Chick Wattenbarger, SPE, Scott Clingman, SPE, and Jasper Dickson, SPE, ExxonMobil Upstream Research Company, prepared for the 2011 SPE Heavy Oil Conference and Exhibition, Kuwait City, Kuwait, 12-14 December. The paper has not been peer reviewed. ExxonMobil and its Canadian affiliate Imperial Oil Resources are pursuing an integrated research program to develop the next-generation heavy-oil-recovery processes that use hydrocarbon solvents as a mobilizing agent. Key benefits of solvent-based processes are improved environmental performance, improved economics, and recovery of a resource that is not achievable with thermal processes. Introduction As used herein, a solvent-assisted process is one in which solvent is added to steam whereas a solvent-based process is one in which solvent is substituted for steam. The term solvent process is used to refer to both solvent-assisted and solvent-based recovery processes. These processes use solvents—typically, light hydrocarbons (e.g., propane or butane) or mixtures of light hydrocarbons (e.g., gas condensates or diluents)—to mobilize the heavy oil in the reservoir. Thermal processes including steam-flooding, cyclic steam stimulation (CSS), and steam-assisted gravity drainage (SAGD) are highly effective recovery processes that enable economical recovery levels that equal or exceed recoveries achieved in most conventional oil fields. Thermal processes are very effective at recovering heavy oil from the best-quality resource: thick, clean sands with high bitumen saturation and high porosity and permeability. However, the efficiency of thermal processes degrades significantly and these processes become less economically attractive in lower-quality resources. Solvent processes have the potential to enable economical recovery of additional resource that cannot be recovered economically with thermal processes. Solvent-Recovery-Process Classification The technical success of thermal-recovery processes lies fundamentally in the three to five order-of-magnitude viscosity reductions that can be achieved when heavy oil is heated to temperatures that can be achieved practically with steam. Solvent/heavy-oil mixtures can achieve similar viscosity reductions in combination with heat or with only the addition of solvent. Fig. 1 shows the effect of temperature and solvent concentration on the resulting mixture viscosity. Typically, heavy-oil-recovery processes endeavor to reduce the flowing-mixture viscosity to 10 cp or lower. While there is a wide variety of solvents that can bring about similar viscosity reductions, the need for relatively low-cost, commercially available, large volumes with acceptable health and environmental characteristics tends to favor the use of relatively pure or mixed light alkanes, such as propane, butane, pentane, gas condensates, or pipeline-quality diluents.

Phase Behaviour and Physical Property Measurements for VAPEX Solvents: Part I. Propane and Athabasca Bitumen

Abstract The saturation pressure and solubility of propane in Athabasca bitumen, as well as the liquid phase densities and viscosities, were measured for temperatures from 10 to 50 °C. Equilibration proved challenging for this fluid mixture and required some experimental modifications that are discussed. Only liquid and liquid-vapour phase regions were observed at propane contents below 20 wt%. A second liquid phase appeared to have formed at higher propane contents. The saturation pressures, where only a single dense phase formed, ranged from 600 to 1,600 kPa and these were fitted with a modification to Raoult's law. Viscosities less than 210 mPa.s were obtained at a propane content of 15.6 wt%. All of the viscosity data of the liquid phase were predicted from the propane and bitumen viscosities using the Lobe mixing rule. Introduction The worldwide original oil-in-place (OOIP) of heavy oil and bitumen is estimated to be approximately 6 trillion barrels. A major part of these resources are in Canada (~36%) and Venezuela (~27%)(1). In Canada, steam-based methods are often employed to improve heavy oil recovery. However, the industry is starting to seek alternatives to these methods because they are energy intensive and are drawing heavily on the available water supply. Solvent-based recovery methods are a potential alternative capable of providing high recovery factors without substantial water requirements(2, 3). One option is the vapour extraction method (VAPEX), which is a solvent-based analogue of the Steam-Assisted Gravity Drainage (SAGD) process(4–7). VAPEX is implemented with a pair of horizontal wells: a production well at the bottom of the reservoir and a solvent injection well located directly above the production well(5), as shown in Figure 1. The vapourized solvent is injected through the injection well and a chamber of solvent vapour forms around the well. At the walls of the chamber, the solvent diffuses into a surface layer of the heavy oil and dramatically reduces its viscosity. The diluted oil layer is then mobile enough to drain down, under the influence of gravity, into the production well. VAPEX performance depends on the viscosity and density of the liquid phase that forms at the edge of the solvent chamber. In order to design and optimize VAPEX and other solvent-based processes, it is critical to be able to determine the diffusivity of the solvent in the heavy oil, identify the phases that form in the solvent and heavy oil mixtures at various temperatures and pressures, and determine the density and viscosity of the liquid phase. Other solvent-based processes (steam and solvent injection for heavy oil recovery and solvent extraction of oil sands) require similar data. Most research on VAPEX has focused on physical model experiments with light alkane solvents; particularly mixtures of methane and propane(3). However, mixtures of carbon dioxide and propane may be a more viable option. Currently, carbon dioxide is expensive, but costs are expected to decrease if environmental incentives to sequester carbon dioxide are introduced. Carbon dioxide may also be a better VAPEX solvent than methane because it is more soluble in heavy oil and reduces the viscosity more(8).

Advances in Diffusivity Measurement of Solvents in Oil Sands

Abstract This work deals with the prediction of mass transfer of solvents in bitumen in the presence and absence of sand through a unified model that uses magnetic resonance response information. Experiments were performed with pairs of solvents and bitumen in the presence of sand and without sand. Low field NMR was used to acquire spectra of the migrating solvent in bitumen or oil sand as a function of time. The experimental results of this work, along with data collected previously on similar systems in the Tomographic Imaging and Porous Media Laboratory, were fit together in a one-dimensional Fickian model. The novelty of the presented approach is not only that the new model matches all the experiments to date, but also that this matching can be done independently and without external input parameters. In previous work, matching could only be achieved if the depth of solvent penetration was provided through external measurements. The present model predicts diffusivities of solvents in bitumen in the presence of sand to be in the same order of magnitude and a bit lower than diffusivities of solvent in bulk bitumen. It is anticipated that this method would be of value when estimates of mass transfer in solvent-based heavy oil processes are attempted in the field. Introduction In solvent-based recovery processes for heavy oil and bitumen, mass transfer phenomena compete with viscous forces, gravity and capillary forces as the predominant means for oil recovery or trapping. In order to understand the relative merit of such forces, one must be able to measure mass transfer at reservoir conditions and potentially verify such measurements in the field. There is considerable literature on the measurement of recovery mechanisms and recovery efficiency through solvent-based processes for heavy oil and bitumen. The bulk of the work presented in the recent literature focuses around the VAPEX (Vapour Extraction) process, but the fundamental work presented can easily apply to any solvent displacement process. If we were to measure mass transfer phenomena in the field, it appears that a possible logging tool with significant potential is magnetic resonance. Thus, the TIPM group has embarked in a project whereby magnetic resonance is used for the determination of bitumen (or heavy oil) solvent interactions. As two miscible fluids are in contact, they will slowly diffuse into each other. This molecular transport of one substance relative to another is known as diffusion. With time, the interface between the fluids will appear as a diffused mixed zone grading from one pure fluid to the other. The mechanism of diffusion happens due to the random motion of molecules(1,2). The diffusion flux between solvent and heavy oil can be defined as the flow due to concentration gradient between solvent and heavy oil. The diffusion phenomena take place when there is no mixing in the system and the only driving force is the concentration gradient, unlike dispersion that is caused due to convective fluid mixing in the porous medium. It was observed that as solvent and heavy oil diffuse into each other, the mobility of hydrogen bearing molecules of both oil and solvent change(3).

Enhanced solvent dissolution into in-situ upgraded heavy oil under different pressures

During a solvent-based heavy oil recovery process, asphaltene precipitation may occur when a solvent is dissolved into heavy oil under certain reservoir conditions. Thus, such an in-situ upgraded heavy oil with a lower asphaltene content is less viscous and easier to be recovered. In this paper, enhanced solvent dissolution into the in-situ upgraded heavy oil is studied. First, three heavy oil samples with different asphaltene contents are tested to model the upgraded heavy oils to rather different extents. Then the propane solubilities in these three heavy oil samples and the viscosities of the three heavy oil–propane systems are measured at five equilibrium pressures ranging from 200 to 800 kPa. Also, the propane diffusivities and oil-swelling factors of the three heavy oil–propane systems are measured by applying the newly developed dynamic pendant drop volume analysis (DPDVA) method in the same pressure range. The detailed experimental results show that the asphaltene content in heavy oil strongly affects propane dissolution into the heavy oil. The propane solubility in the maltenes is found to be the highest, which results in the largest oil-swelling factor among the three heavy oil samples tested. Expectedly, the viscosity of the heavy oil–maltene system is the lowest and accordingly the propane molecular diffusivity in the maltenes is the largest. The in-situ upgrading of heavy oil during a solvent-based recovery process greatly enhances further solvent dissolution into heavy oil and reduces its viscosity.

Investigation of the VAPEX Process Using CT Scanning and Numerical Simulation

Abstract The "VAPEX" process, a solvent analogue of Steam Assisted Gravity Drainage, has attracted considerable attention as a recovery method for heavy oil. However, to date, there are still many questions about the nature and magnitude of basic process mechanisms, and whether the process can produce economic oil rates. The experiments discussed in this paper were aimed at quantifying some of the basic mechanisms, in particular the dispersive mixing mechanism. We have performed a series of topdown solvent injection experiments under varying conditions, utilizing a CT scanner to monitor fluid movements. All of the displacements we have observed are gravity-unstable in the early stages, and characterized by viscous fingering of the solvent into the 5,500 cP oil. After solvent breakthrough, the displacements become stable, dominated by a single solvent finger which has many of the features of a VAPEX solvent chamber. The "mixing parameter" we infer for these experiments using the Butler/Mokrys analytic model is higher than that reported for Hele-Shaw VAPEX experiments. An analysis of localized fluid velocities in the experiments using numerical simulation shows that the enhanced mixing parameter can be understood as a consequence of convective dispersion in the porous medium. By adjusting the amount of physical dispersion, the simulations can match breakthrough time, post-breakthrough oil rates, and the general character of the fingering. A novel type of "quasi-pore scale" simulation grid appears to provide advantages in simulating the unstable period at the beginning of the displacements. Introduction Compared with steam-based processes such as Steam Assisted Gravity Drainage (SAGD) for recovery of heavy oil, solventbased processes offer the possibility of reduced energy consumption and greenhouse gas production. However, they are mechanistically complex, and questions remain regarding their expected performance. To date, no field data are publicly available to answer these questions. One solvent-based process that has been proposed is the Vapour Extraction (VAPEX) process(1, 2). This solvent analogue of SAGD utilizes gravity as the driving agent, and solvent dilution of the heavy oil as the mobilization mechanism. The concept of the process is illustrated in Figure 1. A practical, solvent-based recovery process will depend for its success on the interplay of a number of phenomena. Some of the most important of these are: diffusion/dispersion, viscous fingering, capillary-driven mixing (in the case of a gaseous solvent), and the effects of reservoir heterogeneity. The first three are accessible for study in the laboratory, and understanding their interplay at the laboratory scale is a first step toward predicting their effects in a field process. Numerical simulation is required both to extrapolate laboratory experience to the field scale, and to incorporate the effects of reservoir heterogeneity. The study described in this paper addresses the phenomena of diffusion/dispersion and viscous fingering based on a series of laboratory experiments, combined with numerical simulation. Our initial experiments utilized a liquid solvent; therefore capillary mixing effects were absent. Future work will extend the results to gaseous solvents.